Technique for insulating a wellbore with silicate foam



Aug. 5, mm

J. H. BAYLESS ETAL TECHNIQUE FOR INSQLATING A WELLBQRE WITH SILICATEFOAM Filed Aug. 23, 1968 WALTER L. PENBERTHY, JR. INVENTORS JACK H.BAYLESS ATTQRNEY United States Patent 3,525,399 TECHNIQUE FOR INSULATINGA WELLBORE WITH SILICATE FOAM Jack H. Bayless and Walter L. Penberthy,Jr., Houston,

Tex., assiguors to Esso Production Research Company,

a corporation of Delaware Filed Aug. 23, 1968, Ser. No. 754,887 Int. Cl.E21b 43/24 US. Cl. 166303 8 Claims ABSTRACT OF THE DISCLOSURE A methodand apparatus for thermally insulating a well for use in a thermalprocess for oil recovery. The Well is insulated by boiling a silicatesolution in contact with the well tubing to form a coating of alkalimetal silicate foam on the tubing. The insulated. tubing may befabricated on the surface or within the wellbore.

BACKGROUND OF THE INVENTION Field of the invention This inventionrelates to a process for constructing well elements. More particularly,the invention relates to a process for thermally insulating a wellbore.The invention also relates to an apparatus for insulating the wellbore.

Description of the prior art In the recovery of heavy petroleum crudeoils, the industry has for many years recognized the desirability ofthermal stimulation as a means for lowering the oil viscosity andthereby increasing the production of oil.

One form of thermal stimulation which has recently received wideacceptance by the industry is a process of injecting steam into the welland into the reservoir. This process is a thermal drive technique wheresteam is injected into one well which drives oil before it to a second,producing well. In an alternative method, a single well is used for'both steam injection and production of the oil. The steam is injectedthrough the tubing and into the formation. Injection is theninterrupted, and the well is permitted to heat soak for a period oftime. Following the heat soak, the well is placed on a production cycleand the heated fluids are withdrawn by way of the well to the surface.

Steam injection can increase oil production through a number ofmechanisms. The viscosity of most oils is strongly dependent upon itstemperature. In many cases, the viscosity of the reservoir oil can bereduced by 100 fold or more if the temperature of the oil is increasedseveral hundred degrees. Steam injection can have substantial benefitsin recovering even relatively-light, lowviscosity oils. This isparticularly true where such oils exist in thick, low permeability sandswhere present fracturing techniques are not eflective. In such cases, aminor reduction in viscosity of the reservoir oil can sharply increaseproductivity. Steam injection is also useful in removing wellbore damageat injection and producing wells. Such damage is often attributable toasphaltic or paraffinic components of the crude oil which clog the porespaces of the reservoir sand in the immediate vicinity of the well.Steam injection can be used to remove these deposits from the wellbore.

Injection of high temperature steam which may be 650 F. or even higherdoes, however, present some special operational problems. When the steamis injected through the tubing, there may be substantial transfer ofheat across the annular space to the well casing. When the well casingis firmly cemented into the wellbore, as

it generally is, the thermally induced stresses may result in casingfailure. Moreover, the primary object of any steam injection process isto transfer the thermal energy from the surface of the earth to theoil-bearing formation. Where significant quantities of thermal energyare lost as the steam travels through the tubing string, the process isnaturally less efficient. On even a shallow well,

the thermal losses of the steam during its travel downthe tubing may beso high that the initially high temperature superheated or saturatedsteam will condense into hot water before reaching the formation. Suchcondensation represents a tremendous loss in the amount of thermalenergy that the injected fluid is able to carry into the reservoir.

A number of proposals have been advanced to combat excessive heat lossesin steam injection processes. It has been suggested that a temperatureresistant, thermal packer be employed to isolate the annular spacebetween the casing and injection tubing. Such equipment will reduce heatlosses due to convection between the tubing string and the casing stringby forming a closed, dead-gas space in the annulus. Such specializedequipment is not only highly expensive, but does nothing to preventradiant thermal losses from the injection tubing.

It has been suggested that the wells be completed with a bitumasticcoating. This completion technique utilizes a material to coat thecasing which will melt at high temperature. When melting occurs, thecasing is free to expand thus relieving the stresses which wouldotherwise be placed on the casing due to an increase in its temperature.This method has not proven to be universally successful in preventingcasing failure. In some instances the formation may contact the casingwith suflicient force to prevent free expansion and contraction of thecasing during heating and cooling. Under these circumstances casingfailure is possible due to the unrelieved stresses. Moreover, such acompletion technique does nothing to prevent the loss of thermal energyfrom the injection tubing.

It has been suggested that an inert gas, such as nitrogen, be introducedinto the annular space between the casing and tubing and pumped down theannulus to the formation. This method requires, however, a source ofgas, means for pumping the gas down the annulus, and means forseparating the inert gas from the produced well fluids.

Another means which has been successfully employed to lower heat lossesfrom steam injection tubing is the heat reflector system. This is ashell of heat-reflective, metal pipe which surrounds the tubing string.It is assembled in joints which are equal in length to the joints of thetubing and run into the hole with the tubing string as an integratedunit. The outer shell may be sealed at the top and bottom to prevent theentry of well fluids into the space between the steam injection tubingand the heat reflective shell. Such a system has utility in preventingthe losses of thermal energy from injection tubing due to radiation,conduction, and convection. Such a system, of course, is relativelyexpensive since it requires two strings of metallic pipe-the injectiontubing and the heat reflective shell. Moreover, the use of the heatreflective shell will reduce the diameter of the tubing which may beeffectively employed in any given well. This can be particularlyimportant where multiple strings of tubing are employed in a singlewell.

SUMMARY OF THE INVENTION This invention relates to a process andapparatus for thermally insulating elements of a well, such as a tubingstring. The tubing string is run into the well and set in place. Anaqueous solution of water soluble silicate is introduced into theannular space between the casing and the tubing string. Steam isinjected into the tubing string to raise the temperature of the silicatesolution above its boiling point. Boiling of the silicate solutionremoves its water and deposits a coating of alkali metal silicate foamon the tubing string. The silicate foam is relatively thin and has aremarkable low thermal conductivity.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a schematic representationof a vertical section of the earth showing a well containing casing andsteam injection strings.

FIG. 2 is a schematic representation of the well after deposition of thesilicate foam.

DESCRIPTION OF THE PREFERRED EMBODIMENT In the embodiment shown in FIG.1, a well shown generally at 1-0 is drilled from the surface of theearth 11 to an oil-bearing formation 12. The well has a casing string 13with perforations 14 in the oil bearing formation to permit fluidcommunication between the oil-bearing formation and the casing. Steaminjection tubing 15 extends from the well-head 16 to the oil-bearingformation. The

tubing string is equipped with an inlet line 17 and the casing has aninlet line 18.

A swab cup packer 19 is set on the tubing string and run into the wellto the desired level. A suitable swab cup packer is Type GW, GuibersonCup Packer, sold by Dresser Industries, Inc. A swab cup packer is simplya resilient cup which is sealed on the tubing at its base and extendsoutward to contact the casing with the lip at the top of the packer. Theelastomeric material of the cup may be reinforced with spring steelwires for added strength. The packer cup should be chosen so that theflexible lip has an outside diameter which exceeds the inside diameterof the casing so that immedaite compression of cup against the casing isobtained for instantaneous and positive sealing.

In the practice of this invention the packer cup is installed on thetubing with the base toward the bottom of the well and the lip extendingupward. In this manner, a higher positive pressure above the cup willprevent fluids from moving downward past the cup. The greater thedifferential pressure across the cup, the more tightly the cup willseal. While it is preferred to employ a cup type packer, other packerassemblies known to those skilled in the art may be employed such asanchor type packers, hook wall packers, tension packers, or thermalpackers.

After the tubing string with packer assembly is run into the hole andset in place, an aqueous solution of water soluble slilcate is injectedthrough inlet line 18 into the annular space 20 between the casing andtubing. The packer element will prevent the silicate solution fromtraveling below the packer assembly. Preferably, suflicient solutionwill be employed to fill the annular space.

Following injection of the silicate solution, steam is introduced intothe tubing through inlet line 17, down the tubing string 15, and intothe oil-bearing formation through perforations 14. The casing inlet 18is opened to the atmosphere to permit discharge of the water vapor whichboils from the silicate solution. It is preferred to inject steam at arelatively high temeperature, approximately 600 F., and a relativelyhigh mass flow rate. The high temperatures and high mass flow rates willpermit immediate heating of the tubing string 15 to a high temperatureand will rapidly remove the water from the silicate solution. In someinstances, particularly in wells of extreme depth, it may not bepossible to boil off all of the liquid within the annular space. Thefoam may build up at a rapid rate on the tubing and insulate the annularspace so effectively that the temperature of the liquid remaining in theannular space drops below its boiling point. In Wells of this type, itmay be preferred to employ a reverse circulating device in the tubingstring above the packe Such devices are well known to those skilled inthe art and permit fluid communication between the annular space and thetubing above the packer. These devices can be opened and closed bywireline methods under pressure without moving the tubing or disturbingthe packer setting. The remaining solution may then be displaced fromthe annular space.

As shown in FIG. 2 as the silicate solution boils, the water is removed.and a thin film of alkali metal silicate foam is formed on the exteriorof the tubing string. A more surprising aspect of this invention is thefact that the silicate foam will only deposit on the relatively hotsteam injection tubing and will not deposit on the relatively coolcasing string. This can be a decided advantage, particularly when arelatively permanent packer assembly such as a hook wall or thermalpacker is employed. If substantial quantities of the silicate weredeposited on the casing string, there might be a problem in withdrawingthe tubing and packer assembly when desired.

Minor depositions of silicate foam on tthe interior of the casing stringis not totally undesirable, however, since any silicate deposited uponthe casing will provide further insulation. Due to the high watersolubility of the silicate foam, any minor deposits on the wall of thecasing may be removed by circulating water down the annulus prior topulling the packer.

It is not fully understood why the silicate foam deposits only upon hightemperature surface. It is possible that is a result of the boilingwhich occurs in the immediate vicinity of the high temperature surface.It is also possible that the foam deposition is due to a molecularinteraction between the iron-containing surface and the silicatesolution at high temperatures.

As shown in FIG. 2 after the silicate solution has been boiled and thewater of solution removed, a thin, relatively-hard shell of alkali metalsilicate foam 21 is deposited about the tubing string. This foam hasamazing insulating properties. The thermal conductivity of such a foammay range as low as 7.() 10 (cal.)(cm.)/(sec.) (cm?) (C.).

The silicates employed in the practice of this invention are those ofthe alkali metals which readily dissolve in water. This group iscommonly termed the soluble silicates and includes any of the silicatesof the alkali metals, with the exception of lithium. However, in thepractice of this invention, it is preferred to employ silicate solutionscontaining sodium or potassium, as the alkali metal, due to therelatively low cost and ready commercial availability of such solutions.

When water is removed from solutions of the soluble silicates, theycrystalize to form glass like materials. When the soluble silicates aredried rapidly at boiling temperatures, the solutions intumesce and forma solid mass of bubbles having 30-100 times their original volume. Thedried foam is a light weight glassy material having excel lentstructural and insulating properties.

In the practice of this invention, commercially available sodiumsilicate solutions have been found suitable. Such solutions have adensity of approximately 40 B. at 20 C. and a silica dioxide/sodiumoxide weight ratio of approximately 3.2/1. Alternatively, commerciallyavailable potassium silicate solutions may be employed. Commercialpotassium silicate solutions have a density of ap proximately 30 B. at20 C. and a silica dioxide/potassium oxide weight ratio of approximately2.4/1. The silica dioxide/ alkali metal oxide weight ratio is notcritical to the practice of this invention and may range between 1.3/1and 5.0/1. The density of the solutions may range between 22 B. and 50B. at 20 C. It is only important that sutlicient solids be contained inthe solution so that upon boiling a coating of approximately Vs of aninch or greater will be deposited upon the tubing string.

As is previously stated, it has been found that the silicate foam willform only on the heated surface of the steam injection tubing. In manyinstances it may be necessary to place centralizers on the tubing toprevent contact with the casing wall and consequent transfer of heatfrom the tubing to the casing by conduction. These centralizers can beeasily thermally insulated from the injection tubing by wrapping thetubing at such points with any suitable, heat-insulated material such asasbestos.

Under general operating conditions when extremely high temperature (600F. or higher) steam is injected through the tubing, the swab cup packermay deteriorate permitting steam leakage across the packer. This willgenerally present no problem even though the silicate foam is watersoluble. So long as the casing is shut in, there will be little tendencyfor steam to rise in the annular space and attack the silicate foam. Ifthere is minor encroachment of steam above the packer after itdeteriorates, the thermal insulation of the injection string can bemaintained by utilizing several joints of heat reflective shielding justabove the packer. This heat reflective shielding may also be used toadvantage where a more permanent type packer is employed rather than cuptype packers. This heat reflective shielding at the bottom of the tubingstring will prevent deposition of the silicate foam immediately abovethe packer which might prevent the packer from being pulled. A suitableheat reflective shield is sold by Summit Steam Techniques, Inc. underthe trade name Thermoguard.

The following examples demonstrate the ease with which the suitabilityof various soluble silicate solutions can be determined. One of ordinaryskill in the art using such techniques can readily determine thesuitability for various operating conditions of solutions having variousdensities, silica dioxide/alkali metal oxide weight ratios, percentagesof silica dioxide, percentages of alkali metal oxide, and viscosities.

EXAMPLE I A one-quarter inch O.'D. stainless steel tube, 4 /2 feet inlength was used to approximate a tubing string. A one-half inch I.D.galvanized line pipe was slipped over the tubing string to approximatethe casing and sealed at its top and bottom with an inlet and outlet forthe stainless seel tubing. A tap was drilled in the top of thegalvanized line pipe and the annular space between the tubing and linepipe was partially filled with 135 cc. of sodium silicate solution, 40B., 3.2/1 silica dioxide/ sodium oxide ratio. Steam was injected throughthe center tube at 400 F. and 250 p.s.i.a. After one-half hour, 75 cc.of liquid had boiled out of the annular space. The assembly was thendismantled and it was found that the casing (the outer .pipe) wasessentially devoid of sodium silicate deposits. The tubing (the innerpipe) was coated with a sodium silicate foam shell which was essentiallyuniform and inch in thickness.

The thin deposition of sodium silicate foam was remarkably effective inreducing the transfer of heat from the interior of the tubing to theexterior. With the outer casing removed from the tubing, hightemperature steam (420 F. 325 p.s.i.a.) was injected into one end of thetubing and discharged at substantially the same temperature and pressureat the other end. After injecting the high temperature steam for 45minutes, the highest temperature which was measured on the surface ofthe sodium silicate foam was 150 F.

EXAMPLE II An apparatus similar to that described in Example I wasemployed to evaluate the depositional characteristics of potassiumsilicate solutions and the thermal properties of the resultant potassiumsilicate foam.

The annular space was filled with 600 cc. of a potassium silicatesolution, 30 B. and 24/1 silica dioxide/ potasisum oxide weight ratio.Steam was injected through the inch stainless steel tubing at 400 F. and250 p.s.i.a. for approximately one hour.

After one hour the model was disassembled, and the casing and the tubingstrings were visually inspected. The stainless steel tubing was coatedwith a layer varying from inch to inch in thickness. The wall of thecasing was substantially free of potassium silicate deposits.

The thermal conductivity of potassium silicate foam was evaluated in themanner described in Example I. After injecting high temperature steam(420 F.325 p.s.i.a.) for approximately one-half hour, the highesttemperature reported on the surface of the potassium silicate foam wasapproximately 200 F. The temperature on an uninsulated portion of thestainless steel tubing was 390 F.

In some instances, it may be desirable to coat the tubing at the surfacewith the silicate solution rather than within the well. This may beparticularly desirable in instances where the silicate deposit is to becoated with a waterproofing material before running the insulated tubingstring into the well. Various plastics and resins which are not watersoluble and have the ability to withstand the high temperaturesencountered in thermal operations would be suitable for this purpose.

What is claimed is:

1. A process for thermally insulating a tubing string suspended within awellbore comprising:

(a) injecting into the wellbore-tubing string annular space a solutionconsisting essentially of water and a water soluble silicate;

(b) introducing thermal energy into the tubing string to remove waterfrom the solution and to deposit a coating of the silicate on the tubingstring; and

(c) venting the annular space between the tubing string and the wellboreto discharge water vapor removed from the solution.

2. A process as defined in claim 1 wherein the water is removed from thesolution by passing steam through the tubing string.

3. A process as defined in claim 1 wherein the water soluble silicate isa potassium silicate.

4. A process as defined in claim 1 wherein the water soluble silicate isa sodium silicate.

5. A process as defined in claim 1 further including installing a packeron the tubing string to retain the solution in the annular space untilthe water of solution is removed.

'6. A process as defined in claim 1 further including removing excesssolution from the annular space.

7. A process as defined in claim 1 further including installingcentralizers on the tubing string to prevent tubing-wellbore contact.

8. A process as defined in claim 1 wherein the water soluble silicatehas a density from 22 to 50 B. at 20 C. and a silicate oxide/alkalimetal oxide weight ratio of 1.3/1 to 5.0/1.

References Cited UNITED STATES PATENTS 515,222 2/1894 Heil -1171'35.1 X2,734,578 2/1956 Walter 166-57 X 2,978,361 4/1961 Seidl 117-135.1 X3,276,518 10/ 1966 Schlicht et al. 3,410,344 11/1968 Cornelius 166-3033,438,442 4/ 1969 Pryor et al. 166-57 X 3,451,479 6/1969 Parker 166303OTHER REFERENCES Baker, E. Jack, Jr.: New Applications for SodiumSilicate, 12th National SAMPE Symposium, October, 1967.

ERNEST R. PURSER, Primary Examiner I. A. CALVERT, Assistant Examiner US.Cl. X.R. 1 66-57

